A plunger lift is an apparatus that is used to increase the productivity of oil and gas wells. Nearly all wells produce liquids. In the early stages of a well's life, liquid loading is usually not a problem. When rates are high, the well liquids are carried out of the well tubing by the high velocity gas. As a well declines, a critical velocity is reached below which the heavier liquids do not make it to the surface and start to fall back to the bottom exerting back pressure on the formation, thus loading up the well. A plunger system is a method of unloading gas in high ratio oil wells without interrupting production. In operation, the plunger travels to the bottom of the well where the loading fluid is picked up by the plunger and is brought to the surface removing all liquids in the tubing. The plunger also keeps the tubing free of paraffin, salt or scale build-up. A plunger lift system works by cycling a well open and closed. During the open time a plunger interfaces between a liquid slug and gas. The gas below the plunger will push the plunger and liquid to the surface. This removal of the liquid from the tubing bore allows an additional volume of gas to flow from a producing well. A plunger lift requires sufficient gas presence within the well to be functional in driving the system. Oil wells making no gas are thus not plunger lift candidates.
A typical installation plunger lift system 100 can be seen in FIG. 1. Lubricator assembly 10 is one of the most important components of plunger system 100. Lubricator assembly 10 includes cap 1, integral top bumper spring 2, striking pad 3, and extracting rod 4. Extracting rod 4 may or may not be employed depending on the plunger type. Contained within lubricator assembly 10 is plunger auto catching device 5 and plunger sensing device 6. Sensing device 6 sends a signal to surface controller 15 upon plunger 200 arrival at the well top. Plunger 200 can represent the plunger of the present invention or other prior art plungers. Sensing the plunger is used as a programming input to achieve the desired well production, flow times and wellhead operating pressures. Master valve 7 should be sized correctly for the tubing 9 and plunger 200. An incorrectly sized master valve 7 will not allow plunger 200 to pass through. Master valve 7 should incorporate a full bore opening equal to the tubing 9 size. An oversized valve will allow gas to bypass the plunger causing it to stall in the valve. If the plunger is to be used in a well with relatively high formation pressures, care must be taken to balance tubing 9 size with the casing 8 size. The bottom of a well is typically equipped with a seating nipple/tubing stop 12. Spring standing valve/bottom hole bumper assembly 11 is located near the tubing bottom. The bumper spring is located above the standing valve and can be manufactured as an integral part of the standing valve or as a separate component of the plunger system. The bumper spring typically protects the tubing from plunger impact in the absence of fluid. Fluid accumulating on top of plunger 200 may be carried to the well top by plunger 200.
Surface control equipment usually consists of motor valve(s) 14, sensors 6, pressure recorders 16, etc., and an electronic controller 15 which opens and closes the well at the surface. Well flow ‘F’ proceeds downstream when surface controller 15 opens well head flow valves. Controllers operate on time, or pressure, to open or close the surface valves based on operator-determined requirements for production. Modern electronic controllers incorporate features that are user friendly, easy to program, addressing the shortcomings of mechanical controllers and early electronic controllers. Additional features include: battery life extension through solar panel recharging, computer memory program retention in the event of battery failure and built-in lightning protection. For complex operating conditions, controllers can be purchased that have multiple valve capability to fully automate the production process.
FIGS. 2, 2A, 2B, 2C are side views of the upper sections of various plunger embodiments. Various existing sidewall geometries can be used in conjunction with the present apparatus.                A. Plunger mandrel 20 is shown with solid ring 22 sidewall geometry. Solid sidewall rings 22 can be made of various materials such as steel, poly materials, Teflon®, stainless steel, etc. Inner cut grooves 30 allow sidewall debris to accumulate when a plunger is rising or falling.        B. Plunger mandrel 80 is shown with shifting ring 81 sidewall geometry. Shifting rings 81 allow for continuous contact against the tubing to produce an effective seal with wiping action to ensure that all scale, salt or paraffin is removed from the tubing wall. Shifting rings 81 are individually separated at each upper surface and lower surface by air gap 82.        C. Plunger mandrel 60 has spring-loaded interlocking pads 61 in one or more sections. Interlocking pads 61 expand and contract to compensate for any irregularities in the tubing, thus creating a tight friction seal.        D. Plunger mandrel 70 incorporates a spiral-wound, flexible nylon brush 71 surface to create a seal and allow the plunger to travel despite the presence of sand, coal fines, tubing irregularities, etc.        E. Flexible plungers (not shown) are flexible for coiled tubing and directional holes, and can be used as well in straight standard tubing.        
In each of FIGS. 2, 2A, 2B, 2C, an upper section of the plunger embodiment comprises a top collar shown with a standard American Petroleum Institute (API) internal fishing neck A. If retrieval is required, a spring loaded ball within a retriever and protruding outside its surface would thus fall within the API internal fishing neck at the top of the plunger, wherein the inside diameter of the orifice would increase to allow the ball to spring outward. This condition would allow retrieving of the plunger if, and when, necessary. As shown, each upper section comprises an upper end sleeve 41 and an upper threaded male section 42 used to attach various bottom ends, which will be described below.
Recent practices toward slim-hole wells that utilize coiled tubing also lend themselves to plunger systems. Because of the small tubing diameters, a relatively small amount of liquid may cause a well to load-up, or a relatively small amount of paraffin may plug the tubing.
Plungers use the volume of gas stored in the casing and the formation during the shut-in time to push the liquid load and plunger to the surface when the motor valve opens the well to the sales line or to the atmosphere. To operate a plunger installation, only the pressure and gas volume in the tubing/casing annulus is usually considered as the source of energy for bringing the liquid load and plunger to the surface.
The major forces acting on the cross-sectional area of the bottom of the plunger are:                The pressure of the gas in the casing pushes up on the liquid load and the plunger.        The sales line operating pressure and atmospheric pressure push down on the plunger.        The weight of the liquid and the plunger weight push down on the plunger.        Once the plunger begins moving to the surface, friction between the tubing and the liquid load acts to oppose the plunger.        In addition, friction between the gas and tubing acts to slow the expansion of the gas.        
In certain wells, a plunger will fall towards the well bottom at a relatively high velocity. As the plunger collides with the well bottom, the spring standing valve/bottom hole bumper assembly 11, and/or the seating nipple/tubing stop 12, the impact is absorbed in part by the plunger, the spring standing valve/bottom hole bumper assembly 11, the seating nipple/tubing stop 12 and the well bottom (FIG. 1). A higher velocity could lead to greater impact force and can result in damage to the plunger, and/or the spring standing valve/bottom hole bumper assembly. Bumper springs could collapse over time due to repeated stress caused by impact force. Also, plunger damage can occur resulting in more frequent plunger replacement. Because some wells do not have a bumper spring at the bottom, more of the impact could be absorbed by the plunger itself. A plunger could also rise at a high velocity from the well bottom to the well top. This can occur when liquid levels are low or when an operator allows the plunger to lift prior to proper liquid loading. A high velocity rise could cause damage to the well top apparatus and to the plunger itself. Damage to well apparatus and plunger lift equipment typically increases well maintenance costs.
Prior art designs have utilized plungers with externally located springs to help absorb the energy generated by the plunger force hitting the well bottom. A prior solution is shown in FIG. 3, which shows prior art pad plunger mandrel 60 geometry (see FIG. 2) with a fishing neck top section A, and the addition of an external bottom spring 32 attached via weld 31. The prior art solution with such an external spring, acting as a shock absorber, tends to add reliability problems to both the plunger and well bottom assembly. Failures of the weld and/or spring can occur. In addition, a failed plunger can place more wear and tear on the well bottom seating nipple/tubing stop and spring standing valve/bottom hole bumper assembly.